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Natural Gas and Cellulosic Biomass: a Clean Fuel Combination? Determining the Natural Gas Blending Wall in Biofuel Production Mark Mba Wright, Navid Seifkar, William H. Green, and Yuriy Roman-Leshkov Environ. Sci. Technol., Just Accepted Manuscript • DOI: 10.1021/acs.est.5b00060 • Publication Date (Web): 26 May 2015 Downloaded from http://pubs.acs.org on June 3, 2015
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Natural Gas and Cellulosic Biomass: a Clean Fuel
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Combination?
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Blending Wall in Biofuel Production
a
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10
Natural
Gas
a
Department of Chemical Engineering, Massachusetts Institute of Technology, 77 Massachusetts Ave, Cambridge, MA 02139, USA.
b
Department of Mechanical Engineering, Iowa State University, 04 Marston Hall Ames, IA
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the
Mark M. Wright,a,b Navid Seifkar,c William H. Greena, and Yuriy Román-Leshkov
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7
Determining
50011, USA. c
MIT Energy Initiative, Massachusetts Institute of Technology, 77 Massachusetts Ave, Cambridge, MA 02139, USA
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KEYWORDS – GBTL, Blending Wall, RFS2, biomass, biofuels
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ABSTRACT Natural gas has the potential to increase the biofuel production output by
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combining Gas- and Biomass-to-Liquids (GBTL) processes followed by naphtha and diesel fuel
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synthesis via Fischer-Tropsch (FT). This study reflects on the use of commercial-ready
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configurations of GBTL technologies and the environmental impact of enhancing biofuels with
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natural gas. The autothermal and steam-methane reforming processes for natural gas conversion
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and the gasification of biomass for FT fuel synthesis are modeled to estimate system well-to-
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wheel emissions and compare them to limits established by U.S. renewable fuel mandates. We
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show that natural gas can enhance FT biofuel production by reducing the need for water gas shift
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(WGS) of biomass-derived syngas to achieve appropriate H2:CO ratios. Specifically, fuel yields
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are increased from less than 60 gallons per ton to over 100 gallons per ton with increasing
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natural gas input. However, GBTL facilities would need to limit natural gas use to less than
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19.1% on a LHV energy basis (7.83 wt. %) to avoid exceeding the emissions limits established
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by the Renewable Fuels Standard (RFS2) for clean, advanced biofuels. This effectively
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constitutes a blending limit that constrains the use of natural gas for enhancing the Biomass-To-
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Liquids (BTL) process.
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1. Introduction
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There is growing interest to convert natural gas into transportation fuels due to the discovery of
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large non-conventional gas resources across the world. According to the U.S. Energy
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Information Administration (EIA), proven reserves of natural gas in the U.S. increased from
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191,743 to 283,879 standard billion cubic feet. These discoveries have precipitated a decline in
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U.S. average natural gas prices from a 2008 high of $13.07 per 1000 standard cubic feet (scf)
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($462/m3) to an average of $4.72 per 1000 scf on May, 2014.1 The historically low ratio of
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natural gas to crude oil price encourages the use of natural gas in traditional oil markets, such as
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the transportation fuels sector.
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Gas-to-liquids (GTL) technology has been under development for decades but has only
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recently achieved commercial success.2 On the other hand, biomass-to-liquids (BTL) technology
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has yet to achieve commercial success. In 2011, the United States Environmental Protection
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Agency (EPA) revised the Renewable Fuels Standard (RFS2) annual target for advanced
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cellulosic biofuel production from 250 million gallons to 25.5 million gallons based on projected
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industrial capacity.3 The EPA revised mandates for this category by greater than 90% in
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subsequent years. Under the current RFS2 regulation, gasoline and diesel fuels derived from
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upgrading natural gas syngas do not qualify for credits.
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Concept designs for advanced, cellulosic biofuels are typically based on stand-alone
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biorefineries that limit the use of fossil fuels for process heat or feed. Gasoline emission
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reductions for these concepts range between 70-90%4. The large emission reduction provides
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room for the use of some amount of natural gas (or other fossil fuel) in the biofuel production
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process while keeping emissions at a level that would meet RFS2 regulations. As shown in Table
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1, natural gas is commonly considered as a heat source in thermochemical biomass conversion
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processes where there is insufficient excess fuel gas or biomass for process heat. Combined gas-
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and biomass-to-liquids (GBTL) facilities have the potential to increase the production of clean
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fuels that meet the EPA’s emission and blend market targets. Several studies have evaluated the
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merits of hybrid fossil and biomass conversion technologies that integrate both feeds through the
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production of synthesis gas (syngas) - a mixture of hydrogen and carbon monoxide.5-7 Both
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natural gas and biomass-derived syngas are suitable for the production of drop-in transportation
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fuels via the methanol-to-gasoline (MTG)8 or the Fischer Tropsch (FT)9 upgrading process.
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However, common FT catalysts employ a syngas mixture with a 2:1 H2:CO molar ratio to
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generate the optimal distribution of fuel products, and both natural gas and biomass generate
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syngas streams with H2:CO ratios far away from this optimal ratio. Consequently, further
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processing is required to meet the desired H2:CO specification. Natural gas typically yields a
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syngas with a H2:CO ratio close to 3.7, requiring two-step reforming to separate the excess H2.
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Conversely, biomass gasification yields syngas with a range of H2:CO ratios typically in the
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order of ca. 0.57 due to its lower H2 content relative to natural gas, and the water gas shift
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(WGS) reaction is typically used to increase the H2:CO ratio to a value closer to 2.
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Unfortunately, the WGS reaction consumes CO, thereby lowering the overall carbon yields of
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the resulting biofuel.
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In a GBTL facility, natural gas and biomass-derived syngas can be mixed at varying ratios and
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conditioned using conventional processes to meet the target syngas composition for FT synthesis
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with considerably higher feed-to-fuel yields than BTL processes alone (vide infra). The two
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common technologies for natural gas in this scenario are steam methane reforming (SMR) and
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autothermal reforming (ATR). These technologies generate process and environmental tradeoffs
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some of which are investigated in this study. The syngas from natural gas is fossil in origin and
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the SMR process is typically driven by burning additional natural gas. As such, the use of
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natural gas to balance the final H2:CO ratio becomes an additional source of greenhouse gas
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emissions. These emissions must be taken into account in the life cycle analysis to confirm that
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the biofuel produced is compliant with the RFS2 standard. Alternatively, an ATR converts
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natural gas into syngas with lower CO2 emissions compared to a SMR, but generates a syngas
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stream with a lower H2:CO ratio, thus necessitating significant water-gas-shift of CO to CO2 to
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achieve the 2:1 H2:CO ratio required by the FT unit. Although there is considerable research on
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the technical and environmental performance of GTL and BTL technologies,7, 10 environmental
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assessments for the combined GBTL process are scarce. Notably, complete well-to-wheels
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analyses are non-existent. Given that the conversion of natural gas to liquid fuel contributes to
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greenhouse gas emissions, it is imperative to develop high-fidelity process and environmental
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models to assess the feasibility for emission reductions by blending the natural gas to liquids
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process with biofuel production for the transportation sector.
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Here we show a well-to-wheels analysis that provides metrics for the production of clean,
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sustainable transportation fuels from a biomass-to-liquids process enhanced by natural gas that
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meets the emission reduction requirements set forth by the Environmental Protection Agency
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(EPA) as part of the 2007 Energy Independence and Security Act (EISA).11 Specifically, we
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model how FT biofuel production yields are improved by the use of natural gas, which provides
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the required H2 to achieve appropriate H2:CO ratios for optimal fuel synthesis. We then quantify
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the resulting greenhouse gas emissions and demonstrate that a blending limit exists in GBTL
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processes given that the production of biofuels in GBTL facilities is inherently constrained by
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the RFS2 transportation fuel emission requirements. A sensitivity analysis details how this
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constraint restricts the use of natural gas to a specific range, which varies according to the choice
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of technology and operation conditions. Effectively, this work constitutes the first report of a
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comprehensive RFS2 blend limit wells-to-wheels emissions analysis for a combined GBTL
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production process.
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2. Broader Context
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Natural gas plays a role in almost all fuel synthesis applications either directly as a reacting
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agent or indirectly as a process fuel. Several gas-to-liquids schemes have been developed and
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some have achieved commercial success. The MTG and FT processes can utilize natural gas as
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the primary feedstock for liquid fuel synthesis.10 Similarly, natural gas plays an important role in
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biofuel production given that modern ethanol biorefineries employ natural gas for heat
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generation. Recent studies discuss the possibility of adding natural gas-derived syngas or
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hydrogen for fuel production in biomass gasification12 and pyrolysis biorefineries.13, 14 Life-cycle
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analyses of biomass gasification and pyrolysis processes have estimated that advanced cellulosic
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biofuel emissions meet the 60% reduction mandated by the RFS2.4,
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exclusive use of natural gas for fuel production (GTL) via FT synthesis results in emissions
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(116.89 kgCO2,eq/mmbtu)16 that exceed the 60% emission reduction limit. Therefore, biomass
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addition is required for compliance. Recent studies have focused on stoichiometric addition of
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natural gas to the biofuel production process.12-14 In these studies, the natural gas input rate is
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dictated by the hydrogen input required by the chemical reaction. However, some configurations
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fail to meet the EPA emission reduction mandates. It is highly important to identify how much
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natural gas can be added to produce clean, advanced biofuels as defined by the RFS2. This study
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seeks to address this question in the context of the GBTL platform in a manner that can be
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extended to other biofuel production processes.
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Table 1. Biomass and natural gas use and well-to-wheel emissions in biofuel production
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processes Process/ Product
Biomass Input (tonne/ day)
Natural Yield Gas (gal/ton Input biomass) (tonne/ day)
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On the other hand,
Well-toWheels Emissions (grams CO2,eq/ mmbtu)
Petroleum Refining/
-
-
-
98,00017
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99.7
23,00017
867†
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25,00017
Diesel 16 Fermentation/ 2000 Ethanol18 Gasification/
2000
FT Fuels 12
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Bio-oil Upgrading/
2000
154.2†
81.4
12,00017,
2000
187.2
100
39,00017,
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Gasoline 13 19 Bio-oil Upgrading/
20
Gasoline14 122
†Based on 0.317 kg H2/kg CH4 steam reforming yield
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‡Not Available
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3. Methodology
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This study combines an Aspen PlusTM process model of the combined Gas- and Biomass-to-
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liquids process (GBTL) with well-to-wheels emission analysis based on the Greenhouse Gases,
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Regulated Emissions, and Energy Use in Transportation Model (GREET) developed by Argonne
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National Laboratory.16 A GBTL facility converts natural gas and biomass into synthetic liquid
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fuels via the MTG or FT synthesis process. While several GBTL technologies that produce
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transportation fuels compatible with existing vehicle and fuel infrastructure have been
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proposed,10 this study focuses on the FT synthesis pathway to naphtha- and diesel-range blend
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stock fuels.
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3.1 Process Description
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3.1.1 Reactor Design: Our GBTL process model is based on the baseline flowsheet model
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developed by Field and Brasington21 and subsequently enhanced by Field and Brasington at
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MIT. The flowsheet was adapted to combined biomass and natural gas conversion to syngas and
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subsequent catalytic synthesis to FT liquids followed by upgrading to naphtha and diesel range
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blend stock fuels. Figure 1 summarizes the key processing steps for the GBTL concept and
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highlights the intermediate conversion steps and auxiliary facilities. The key enabling
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technologies are biomass gasification and natural gas reforming (autothermal or steam). The
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facility capacity in this study varies with the biomass to natural gas feed rates with a
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representative case of 1992 and 168 tonnes per day of biomass and natural gas respectively.
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This study employs an entrained flow gasifier to convert biomass into syngas with a low
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impurity content and high energy value. There are several commercial entrained flow gasifiers22
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that operate at elevated temperatures (≥ 1200 ◦C) to enable high conversion efficiency and tar
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destruction. However, there is limited commercial experience of processing biomass with
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entrained flow reactors.
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Our process employs either an autothermal or steam methane reforming reactor to convert
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natural gas to synthesis gas.10 These reactors differ by the heat delivery method and optimal
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H2O/O2:C ratios. Autothermal reactors generate requisite heat by partial combustion of natural
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gas within the front-end of the reactor; steam-methane reforming relies on indirect heat delivered
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from an external furnace. The autothermal reformer commonly employs a lower H2O:C (0.6:1)
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molar ratio than the ratio employed in the steam-methane reformer (2:1). Finally, the autothermal
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reformer employs a 0.25:1 O2:C molar ratio whereas there is no O2 input in the steam-methane
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configuration. An alternative to both systems is the Partial Oxidation reformer (POX), which
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employs O2 without steam to generate syngas with a 1.8:1 H2:CO molar ratio, but suffers from
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safety concerns.10 These reactors can be operated over a wide range of conditions. We varied
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temperature, pressure, steam to carbon ratio, and oxygen to carbon ratio in the sensitivity
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analysis.
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Steam-methane reforming reactions are described by Equations 1a, representing the SMR
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operation, and 1b, representing the autothermal reactor. At temperatures of 200 to 350 °C, the
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water-gas-shift reaction (1c) increases the final H2:CO ratio. Steam reforming generates an exit
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gas with a H2:CO ratio of 3.7 or higher depending on the steam input rate and operating
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conditions. Autothermal reforming (ATR) yields a H2:CO molar ratio that approaches the
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Fischer-Tropsch synthesis requirement of 2.0. CH4+H2O ↔ 3H2+CO
(1a)
4CH4+O2+2H2O ↔ 10H2+4CO
(1b)
CO+H2O ↔ CO2+H2
(1c)
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This study assumes that the entrained flow gasifier operates at 1400 ◦C and 45 bar pressure.
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The gasification feed includes a steam input based on a 0.16 steam to carbon molar ratio. Heat is
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generated within the reactor with a variable oxygen input sufficient to maintain the reactor
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temperature (calculated 0.37 O2:C molar ratio). The autothermal reactor operates at 950 ◦C and
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25 bar with 0.6 steam to carbon and 0.64 oxygen to carbon molar ratios.10 The steam-methane
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reformer operates at 950 ◦C and 25 bar with a 2.0 steam to carbon ratio and zero oxygen input.
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The heat for steam reforming is provided by combusting natural gas with air in a dedicated
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furnace. Table 2 summarizes the reactor operating conditions.
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Table 3 describes the properties of delivered willow and natural gas (pipeline quality) at the
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facility gate. The facility receives willow with a 50 wt. % moisture content and pressurized
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natural gas via pipeline. The natural gas composition shown here is representative of the North
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American market.23
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Table 2 Biomass gasification and natural gas reforming reactor technology and operating conditions Entrained Autothermal SteamFlow Reformer Methane Gasifier Reformer (ATR) (EFG) (SMR) Temperature 1400 (°C)
950
950
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Pressure (bar)
45
25
25
H2O:C molar ratio
0.16
0.6
2
0.64
0
Direct
Indirect
O2:C molar 0.37* ratio Heat Delivery 181
Direct
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Adjusted for adiabatic operation
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3.1.2 Process Design The overall process model includes distinct blocks representing the
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various process and auxiliary units of the GBTL plant. The process units include biomass
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feedstock preparation, air separation, gasification, natural gas reforming, water gas shift, acid gas
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removal, CO2 recovery, sulphur recovery, Fischer-Tropsch (FT) synthesis, hydrogen recovery,
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and product upgrading.
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Table 3 Pipeline quality natural gas and delivered willow composition and properties Natural Gas23
Willow (dry basis)
Methane (vol %)
93.42 Carbon (wt. 49.32 %)
Ethane (vol %)
5.54
Hydrogen (wt. %)
5.94
N2 (vol %)
0.55
Nitrogen (wt. %)
0.63
CO2 (vol %)
